This disclosure relates generally to the field of subsurface formation fracture evaluation. More specifically, the disclosure relates to techniques for evaluating fracture aperture using measurements from multi-axial electromagnetic induction well logging instruments.
A tri-axial electromagnetic induction well logging tool such as one sold under the trademark RT SCANNER, which is a trademark of Schlumberger Technology Corporation, Sugar Land, Tex., measures 9-component apparent conductivity tensors (σm(i, j, k), i, j=x, y, z) at a plurality of receiver spacings from a transmitter, wherein each spacing is represented by the index k. FIG. 2 schematically illustrates such a tri-axial tool 10 and the component tensor measurement C. The instrument 10 may include one or more multi-axial electromagnetic transmitters T disposed on the instrument 10, and have one or more multi-axial electromagnetic receivers (usually consisting of a main receiver RM and a balancing or “bucking” receiver RB to attenuate direct induction effects) at one or more axially spaced apart positions along the longitudinal axis z of the tool 10. The RT SCANNER instrument uses triaxial transmitters and receivers, wherein the transmitters and receivers have three, mutually orthogonal coils having magnetic dipole axes oriented along the tool axis z and along two other mutually orthogonal directions shown at x and y. The tool's measurements in the present example may be obtained in the frequency domain by energizing the transmitter T with a continuous wave (CW) having one or more discrete frequencies to enhance the signal-to-noise ratio. However, measurements of the same information content could also be obtained and used from time domain signals through a Fourier decomposition process by energizing the transmitter T with one or more types of transient currents. This is a well-known physics principle of frequency-time duality. Voltages induced in each coil of one of the receivers RM/RB is shown in the tensor C represented by the voltage V with a two letter subscript as explained above representing the axis (x, y or z) of the transmitter coil used and the axis of the receiver coil (x, y or z) used to make the particular voltage measurements. The voltage measurements in tensor C may be processed to obtain the described apparent conductivity tensors. Subsurface formation properties, such as horizontal and vertical conductivities (σh, σv), relative dip angle (θ) and the dip azimuthal direction (Φ), as well as borehole/tool properties, such as mud conductivity (σmud), wellbore diameter (hd), tool eccentering distance (decc), tool eccentering azimuthal angle (ψ), all affect the measurements of voltages used to determine the conductivity tensors.
FIG. 3A illustrates a top view, and FIG. 3B shows an oblique view of an eccentered tool 10 in a wellbore 12 through an anisotropic formation F with a non-zero dip angle (θ). Eccentering of the tool 10 is shown by decc and the azimuthal angle of the dip azimuth is represented by φ. The tool 10 eccentering azimuthal angle is shown by ψ. The above description is to provide a frame of reference to understand an example method according to the present disclosure.
Using a simplified model of layered anisotropic formation traversed obliquely by the wellbore 12, the response of the conductivity tensors depends on the above eight parameters in a very complicated manner. The effects of the wellbore and instrument orientation and position to the measured conductivity tensors may be very large even in oil base mud (OBM) environment. Through an inversion technique the above wellbore and formation parameters can be calculated and the borehole effects can be removed from the measured conductivity tensors.
The formation parameters (vertical and horizontal conductivities, dip and dip azimuth) may be displayed substantially in real-time (as computer by a processor near the wellbore, see FIG. 1A and FIG. 1B) to help make various decisions related to the drilling and completion of the well in a given field. The resistivites (the inverse of conductivities) of the subsurface formations determinable by a tool such as illustrated in FIG. 2 are known in the art to be used, for example, to delineate low resistivity laminated hydrocarbon bearing formations. The dip and dip azimuth are known to be used to map the structure of the formations in a scale much finer than that provided by, e.g., surface reflection seismic. One of the important items of information that may affect the drilling and completion decisions of any particular wellbore is whether the wellbore has traversed significant fracture zones. Fractures occur in the formation due to the tectonic force over the past geological time. Fractures could also be induced by the drilling operation. Large deep fracture systems can sometime be the key factor that allows the production of oil and gas from the pay zone. Large deep fracture system traversed by the borehole could also cause loss of drilling mud. Accordingly, knowing the location of the fracture zone and the fracture plane orientation can significantly improve the drilling and completion decision.
Very thin fractures with large planar extent filled with OBM may block the induced current in the formation resulting from electromagnetic induction effects of energizing the transmitter T on the tool and could produce significant anomalies in the inverted formation parameters compared with those from the same formation without the fractures. The size of such anomalies may depend on the formation resistivity (Rh, Rv), the size of the fracture plane, and the relative dip and azimuth between the fracture plane and the layering structure of the formation, among other things. If the fracture plane is nearly parallel to the layering structure of the formation, the effects of the fracture on measurements made by an instrument such as shown in FIG. 2 may be relatively small. On the other hand, if the fracture plane is perpendicular to the layering structure of the formation, the effect of the fracture may dominate the response of the tool. A fracture system often encountered by wellbores is that of substantially horizontal layered formations with vertical fractures. Accordingly, techniques for characterizing such fractures using multi-axial (e.g., tri-axial) electromagnetic induction measurements may be useful in this regard.